Horizontal well technology is being used today on a worldwide basis to improve hydrocarbon recovery. Such technology may comprise methods and apparatus which increase the reservoir drainage area, which delay water and gas coning and which increase production rate. A problem which may exist in longer, highly-deviated and horizontal wells is non-uniform flow profiles along the length of the horizontal section. This problem may arise because of non-uniform drawdown applied to the reservoir along the length of the horizontal section and because of variations in reservoir pressure, permeability, and mobility of fluids. This non-uniform flow profile may cause numerous problems, e.g., premature water or gas breakthrough and screen plugging and erosion (in sand control wells), and may severely diminish well life and profitability.
In horizontal injection wells, the same phenomenon applied in reverse may result in uneven distribution of injection fluids leaving parts of the reservoir un-swept and resulting in loss of recoverable hydrocarbons.
Reservoir pressure variations and pressure drop inside the wellbore may cause fluids to be produced (in producer wells) or injected (in injector wells) at non-uniform rates. This may be especially problematic in long horizontal wells where pressure drop along the horizontal section of the wellbore causes maximum pressure drop at the heel of the well causing the heel to produce or accept injection fluid at a higher rate than at the toe of the well. This may cause uneven sweep in injector wells and undesirable early water breakthrough in producer wells. Pressure variations along the reservoir make it even more difficult to achieve an even production/injection profile along the whole zone of interest.
Various methods are available, which are directed to achieving uniform production/injection across the whole length of the wellbore. These methods range from simple techniques like selective perforating to sophisticated intelligent completions which use downhole flow control valves and pressure/temperature measurements that allow one to control drawdown and flow rate from various sections of the wellbore.
Another available method is to place pre-set fixed nozzles or some other means of providing a pressure drop between reservoir and production tubing. Such a nozzle may comprise a choke or valve that restricts the flow rate through the system. the pressure drop caused by these nozzles varies in different parts of the wellbore depending upon the reservoir characteristics to achieve even flow rate along the length of the well bore.
While intelligent completion methods may result in acceptable control of drawdown and flow, such methods require hydraulic and/or electric control lines which limit the application of such methods and which add to the overall cost of the completion. On the other hand, pre-set pressure drop techniques (i.e., pre-set fixed nozzles) are completely passive, have a limited control on the actual flow rate through them, and have no ability to adjust the choke size after the completion is in place. By design, these fixed flow area pressure drop device techniques require uneven flow rate through them to vary the pressure drop across them.
In addition, it has been observed during production logging of wells completed with such passive devices that under certain flow conditions, fluids may cross flow from one section of the wellbore to another, because these devices provide no means to prevent flow of fluids from high to low pressure regions of the reservoir.